Hydraulic fracturing was developed approximately fifty years ago as a means of stimulating the production of oil or gas wells. A hydraulic fracturing stimulation treatment is achieved by pumping a selected fractionating fluid ("frac fluid") into the formation zone of interest at a pressure that exceeds the tensil strength of the rock formation plus its closure or stress pressure. The formation will thus be caused to rupture and the fracture will extend in a plane that is perpendicular to the direction of the least stress at that point.
Over the years, the magnitude of hydraulic fracturing stimulation treatments has increased to a point where thousands of gallons of fluid carring many tons of proppant, such as sand, are used for some treatments. Fracture length is very important to the success of the treatment, and as the size of the treatments increased in an attempt to extend a newly created fracture farther and farther from the well bore and deeper into the matrix of the formation, a fluid loss problem became prevalent. Fracture extension can only be achieved with fluid which is retained in the fracture, but since pressure is greater in the fracture than it is in the surrounding formation, the frac fluid tends to leak off into the matrix of the formation. This leakage not only reduced significantly the fracture length or extension which could be attained with a given amount of frac fluid, but the fluid lost into the formation can, in some instances, damage the permeability of the rock. Also, the loss of fluid from the fracture may increase the proppant to fluid ratio to the extent that a "screen out" occurs. A screen out is a condition where the proppant concentration becomes too high for the fluid to carry which in turn causes the pumping pressure to become excessive. When this happens, the treatment must be terminated and the clean-up required is both time consuming and expensive.
To combat frac fluid leakage, various fluid loss additives have been incorporated into the fluid used in the fracturing treatment. Often, these fluid loss additives consist of a finely ground or powdered material, and very few insoluble granular materials have escaped having been employed as a fluid loss aid at one time or another. The theory behind the use of such materials is that the individual particles will plug the pore spaces in the fracture wall, thereby restricting the flow of frac fluid from the fracture into the formation matrix.
The problem experienced with insoluble fluid loss additives is that once the pressure within the fracture is released, and as the well begins to produce, these additives are seldom flushed out of the formation. To be effective, the fluid loss material must wash off the fracture face, thereby clearing the pore spaces in the formation to permit the flow of hydrocarbon materials from the formation in to the fracture and from there to the surface. However, many insoluble fluid loss additives continue to plug the matrix to reduce hydrocarbon flow, and that which is washed off the fracture face during clean-up often falls into the proppant bed and remains in the well. Fluid loss additives trapped in the proppant bed reduce the permeability of the bed and in turn the production of the well is reduced.
A further disadvantage of insoluble granular materials when used as a fluid loss additive is their lack of malleability. The pores in a rock formation matrix are of irregular shape and are often difficult to plug with non-malleable particles. More malleable materials, such as starches, waxes and gels have been used as fluid loss additives in place of insoluble granular materials, but again these materials have properties which, for some applications, prove to be disadvantageous. Starches require the addition of a breaker material before they can be removed from the fracture wall, while waxes leave a residue which restricts hydrocarbon flow. Also, wax particles tend to stick under the valve seats of pumps for the frac fluid causing pump malfunction. Finally, gels, such as guar gel, form a filter cake or thick coating of dehydrated gel on the fracture face which is harmful to hydrocarbon production and very difficult to remove.
Attempts have been made to use water soluble, oil insoluble soap to plug the porous water-rich strata of a subterranean formation so that water from these strata will not be selectively produced by driving fluid to adversely affect oil-to-water ratios. However, as indicated by U.S. Pat. No. 3,865,189 to Friedman, a soap is used for this purpose which chemically reacts in the subterranean formation with reactants either already present in the formation or with reactants injected with the soap to produce a water insoluble, oil soluble soap. The use of a soap which becomes water insoluble is not suitable for use as a fluid loss additive in a hydraulic fracturing stimulation treatment, for such soap becomes an insoluble fluid loss additive which cannot be removed by water at the end of the fractionating process. Instead it would remain to block oil flow until ultimately it would dissolve to foul the oil with soap.
Practically all known fluid loss additives presently in use tend to damage the "regain" or production of a well to some degree. However, the fracture or fracture extension created by a hydraulic fracturing treatment greatly increases the relative hydrocarbon drainage area, and thus total production from the enlarged drainage area is usually much greater than it was prior to treatment. The amount of damage which may result is always a matter of great concern during the selection of a fluid loss additive material for a particular application, and there is an on-going quest to find economical, less damaging, biodegradable and non-residue forming materials which may be effectively used for this purpose.